Estimating solar irradiance components from plane of array irradiance and global horizontal irradiance

ABSTRACT

A computer implemented method of estimating at least one solar irradiance component, the method comprising: obtaining a sensor measurement from an instrument to provide a measured global horizontal irradiance (GHI measured ), wherein the measured global horizontal irradiance (GHI measured ) consists of at least an estimated diffuse horizontal irradiance (DHI estimated ) and an estimated direct normal irradiance (DNI estimated ); providing at least one modeled component, wherein at least one of the modeled components is a modeled global horizontal irradiance based on an atmospheric model (GHI model ); calculating an irradiance estimate modifier (IMOD) in a computing device according to the measured global horizontal irradiance (GHI measured ) and the modeled global horizontal irradiance (GHI model ); and providing at least one estimated solar irradiance component by a computing device according to the irradiance estimate modifier (IMOD) and at least one modeled component.

This application claims priority to provisional patent application No.61/546,824 filed Oct. 13, 2011 entitled “Estimating Solar IrradianceComponents from Plane of Array Irradiance and Global HorizontalIrradiance”, and is a continuation-in-part of application Ser. No.12/777,224 entitled “IRRADIANCE MAPPING LEVERAGING A DISTRIBUTED NETWORKOF SOLAR PHOTOVOLTAIC SYSTEMS” which is a continuation-in-part ofapplication Ser. No. 11/949,035 filed Dec. 2, 2007 now issued as U.S.Pat. No. 7,742,897 entitled “Systems and Methods for Monitoring andDiagnosing the Power Generated by Renewable Power Systems” and claimspriority to and is a continuation-in-part of co-pending application Ser.No. 11/673,649 Feb. 12, 2007 entitled “Systems and Methods for ProvidingRenewable Power Systems by Aggregate Cost and Usage” all of which areincorporated herein by reference.

With the increasing popularity of solar panels, it has becomeincreasingly more desirable to map the relative concentration of solarradiation hitting the earth's surface in different geographic regions.This may be useful to make determination of whether to buy aphotovoltaic solar system, the appropriate size of the system and theproper angle of installation. The process of mapping the intensity ofthe sun is generally referred to as solar resource assessment. Theoutput of solar resource assessments are databases that catalog theregional intensity of the solar resource, on a given number of minutesincrement or an hourly basis, over the course of many years. Thedatabases are often displayed as maps, having an appearance similar totopographic maps, and shadings corresponding to the intensity of theaverage annual solar resource. These maps are referred to as irradiancemaps.

Solar irradiance, the energy from the Sun's electromagnetic radiation,has a wide range of applications from meteorology to agronomy to solarpower. Constructing detailed irradiance maps is a challenging butimportant goal. Irradiance maps can be useful for a number of things,from estimating crop growth to estimating potential output from PVsystems. Developing irradiance maps can be challenging becauseirradiance sensors are too expensive to deploy widely, andsatellite-based methodologies tend to have wide margins of error.

Detailed site-specific irradiance is important in a number of differentways, particularly in the context of solar power. Recent, real-time andforecasted irradiance for specific locations are important forunderstanding the performance of PV systems in the field, bothsmall-scale distributed systems and large-scale solar farms. Granularirradiance data, representing typical irradiance values in specificlocations, its importance for estimating potential output from futureinstallations of solar PV systems in those specific locations. Acquiringirradiance data generally comes from one of four sources, (1)Satellite-based irradiance estimates, which while fairly reliable overlong time horizons, lack enough precision to a) fully characterize thepotential solar resources for existing system performance assessmentsor, b) accurately estimate potential output from a new system underdesign consideration; (2) Weather station data from somewhere in thesame region. While this represents actually measured data, there are notmany of these weather stations around, so the weather data is generallynot precise enough for the location under consideration; (3) Historicalirradiance studies: while these studies may provide reasonably accurateestimates based on historical experience, they do not solve the problemof the need for recent real-time and forecasted irradiance for specificlocations; (4) One-off studies of irradiance: sometimes people mayinvest in irradiance monitoring equipment for a particular site that isunder consideration for construction of a solar system. While precise,this solution is generally extremely expensive and time consuming.

The amount of solar irradiance reaching a surface on Earth is composedof direct, diffuse, and ground reflected irradiance. These differentcomponents of irradiance often have different impacts on objects. Forexample, the performance of solar panels under direct and diffuse lightis different. Many commonly deployed irradiance sensors do not provideinformation on the different direct, diffuse, and ground reflectedirradiance components, however, and instead simply provide aggregateglobal horizontal irradiance (GHI) or plane of array irradiance (IPoA)measurements. Atmospheric models may estimate irradiance at the earth'ssurface from weather data or satellite imagery, and these models mayprovide estimates of the direct, diffuse, ground reflected irradiancevalues in addition to GHI or IPoA values. The present invention providesmethods for combining sensor measurements of aggregate GHI or IPoA, andatmospheric models for irradiance, including direct and diffusecomponents to provide accurate estimates of direct, diffuse, and groundreflected solar irradiance components.

In the case of global horizontal irradiance (GHI), the total amount ofsolar irradiance reaching a surface horizontal to the ground, irradianceis composed of diffuse horizontal irradiance (DHI) and direct normalirradiance (DNI) corrected for solar position, with no ground reflectedirradiance due to the horizontal positioning. Using this relationshipand empirical studies, methodology was developed to estimate DNI, DHI,IPDA, plane of array direct irradiance (HBEAM), plane of array diffuseirradiance (HDIFF), and plane of array ground reflected irradiance(HGRF) from GHI. While this methodology has been proven effective, it isrestricted to using GHI for making all estimates and is thus subject tobiases and errors associated with the input. Additional types of solarirradiance observations, such as IPoA, would help to reduce model biasand improve accuracy. This methodology provides logic for improvingestimates of solar irradiance components (GHI, DNI, DHI, IPoA, HBEAM,HDIFF, HGRF) by leveraging sensors recording GHI or IPoA and atmosphericsolar irradiance models.

These and other features, aspects and advantages of the presentinvention will become better understood with reference to the followingdescription and claims.

SUMMARY OF THE INVENTION

The present invention relates generally to systems and methods forestimating solar irradiance components.

According to one embodiment of the present invention, a computerimplemented method of estimating at least one solar irradiancecomponent, the method comprising: obtaining a sensor measurement from aninstrument to provide a measured global horizontal irradiance(GHI_(measured)), wherein the measured global horizontal irradiance(GHI_(measured)) consists of at least an estimated diffuse horizontalirradiance (DHI_(estimated)) and an estimated direct normal irradiance(DNI_(estimated)); providing at least one modeled component, wherein atleast one of the modeled components is a modeled global horizontalirradiance based on an atmospheric model (GHI_(model)); calculating anirradiance estimate modifier (IMOD) in a computing device according tothe measured global horizontal irradiance (GHI_(measured)) and themodeled global horizontal irradiance (GHI_(model)); providing at leastestimated one solar irradiance component by a computing device accordingto the irradiance estimate modifier (IMOD) and at least one modeledcomponent.

According to another embodiment of the present invention, a computerimplemented method of estimating at least one solar irradiancecomponent, the method comprising: obtaining a sensor measurement toprovide a measured plane of array irradiance (IPoA_(measured)), whereinthe measured plane of array irradiance (IPoA_(measured)) consists of atleast an estimated plane of array direct irradiance (HBEAM_(estimated)),an estimated plane of array diffuse irradiance (HDIFF_(estimated)) andplane of array ground reflected irradiance (HGRF_(estimated)); providingat least one modeled component, wherein at least one of the modeledcomponents is a modeled plane of array irradiance based on anatmospheric model (IPoA_(model)); calculating an irradiance estimatemodifier (IMOD) in a computing device according to the measured plane ofarray irradiance (IPoA_(measured)) and modeled plane of array irradiancebased on an atmospheric model (IPoA_(model)); providing at least oneestimated solar irradiance component by a computing device according tothe irradiance estimate modifier (IMOD) and at least one modeledcomponent.

These and other features, aspects and advantages of the presentinvention will become better understood with reference to the followingdescription and claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 depicts the present invention;

FIG. 2 depicts the present invention;

FIG. 3 depicts the present invention;

FIG. 4 depicts the present invention;

FIG. 5 depicts the present invention;

FIG. 6 depicts the present invention;

FIG. 7 depicts the present invention;

FIG. 8 depicts the present invention;

FIG. 9 depicts the present invention;

FIG. 10 depicts the present invention;

FIG. 11 depicts the present invention;

FIG. 12 depicts the present invention;

FIG. 13 depicts the present invention;

FIG. 14 depicts the present invention; and

FIG. 15 depicts the present invention.

DETAILED DESCRIPTION OF THE INVENTION

The following detailed description is of the best currently contemplatedmodes of carrying out the invention. The description is not to be takenin a limiting sense, but is made merely for the purpose of illustratingthe general principles of the invention, since the scope of theinvention is best defined by the appended claims.

FIGS. 1-5 provide examples of a monitored electrical system (in thiscase a renewable power system and more specifically a photovoltaic arraysolar panel also referred to herein as a solar photovoltaic system orsolar powered system) from which information may be obtained. Accordingto the example shown, there is a server 10 and at least one monitoredelectrical system (e.g. 102, 104, 106, 108, 110, 112) which is providedto a user or consumer. There may be at least one data server (10), atleast one generation monitoring device (16) in communication with themonitored electrical system (at premise monitored electrical system(30)) and at least one communication node (22) in communication with atleast one of the monitored electrical system (30), the generationmonitoring device (16) and the data server (10). It should be understoodthe data server may be a single computer, a distributed network ofcomputers, a dedicated server, any computer processor implemented deviceor a network of computer processor implemented devices, as would beappreciated by those of skill in the art. The monitored electricalsystem may have background constants that are entered into the systemduring data setup; populating this part of the data structure is one ofthe initial steps to the process. During this time, all required (orpotentially required) background information may be loaded into thesystem. This data will later be used for system calculations anddiagnostics. Background constants may include: (1) Full Calendar withsunrise and sunset according to latitude throughout the year; (2)Insolation or ‘incident solar radiation’: This is the actual amount ofsunlight falling on a specific geographical location. There are expectedamounts of radiation which will fall on an area each day, as well as anannual figure. Specific Insolation is calculated as kWh/m2/day. Theimportance of this variable is that it can combine several otherBackground Constants; and (3) Location Functionality. It is envisionedthat some of this information may be input and some may be determinedautomatically according to the method disclosed herein. The presentinvention helps determine the proximity of each system to each othersystem, and forms a part of the methods used to determine the geographicaverage of the renewable energy systems. While there are differentspecific methods of implementing Location Functionality, generally thisrelies on a large database of locations which are tied to zones. Becausethe relational distances between the zones are stored within thesoftware, the distances between any two locations can then be easily andaccurately calculated.

There may be the step of determining at least one diagnostic variablefor each monitored electrical system (30). These are the variables whichaffect the diagnostics. Examples include: (1) Adjustments to thepermitted size of each zone. When there are fewer systems within anarea, the algorithm may be adjusted to allow for a statisticallyaccurate comparison, but this would also reduce the ability of thecomparison to control as well for weather, etc., since there may be morevariances over the distance; (2) Adjustments to the sensitivity of thediagnostics. Changing thresholds will impact when a particular renewableenergy system is identified by the software as having an issue. Eachdiagnostic variable is saved into at least one data server.

At least one system coefficient for each monitored electrical system maybe determined and saved in the data server(s). These are set up wheneach new renewable energy system is entered into the software, and theyprovide key information about the expected performance of each system.The coefficients will generally stay the same for the life of thesystem. Not all system coefficients will be used in each comparativediagnostic, but they all may be used at some point to provide additionalfunctionality to the process. One critical aspect of the systemcoefficients is that ALL coefficients for all renewable energy systemsmust be assigned using the same approach and rules. The reason for thisis that if the system coefficients are not uniformly applied, thenormalized performance values (described below) will not be accurate.The items which can make up the system coefficients include: (1)expected generation by day, month and year for the system; (2) expectedgeneration on an ongoing basis (e.g. average generation each day,regardless of time of the year); (3) renewable energy system size; (4)system technology; (5) system tolerances (e.g. how accurate informationfrom the system's components will be); (6) system shading; (7) systemorientation; and (8) an ‘Adjustment Factor’ which can be entered byadmin to adjust for how the system actually works to reduce ‘false’signals if the system does not work as initially expected. This isrepresented as a percentage affecting the calculations. While it is agoal of the present invention to automatically detect many systemcoefficients, some system coefficients may be user input.

The energy generated by each monitored electrical system is recorded andthe data server may then determine comparative information based upon atleast one of the background constant, the diagnostic variable, thesystem coefficient and the energy generated to determine a comparativevalue of the monitored electrical system. The term comparative value isintended to include any value that compares one system to another systemor a group of systems. For example, this may be as simple as an“underperforming” designation when the system's performance is less thananother system or group of systems performance in terms of powergenerated.

The normalized performance is then calculated. This is an ongoingcalculation which is done for each monitored electrical system which isconnected to the software. Essentially, the Normalized Performance is amonitored electrical system's actual performance for a given time periodmultiplied by its individual System Coefficient.

The formula for this for a given time period is: NP=Gen*SC

This equation is relevant to performing comparative information andcomparative diagnostics since it enables the results from disparatesystems to be ‘normalized’ and therefore directly compared. Thesenormalized performance readings can then aggregated into larger periods(24 hours, 7 days, 1 month) for comparison.

The comparative information may be a ‘geographic average’. Thegeographic average may be calculated by an algorithm which produces anaverage of the normalized performances for each area covered. Onepurpose is to be able to efficiently perform comparative diagnosticsregularly (e.g. every 5 minutes) for a large number of areas containinga large number of renewable energy systems without overly taxing theservers' processors. According to one embodiment, the main steps of thisare as follows: (1) The software will randomly select a predeterminednumber (for example forty (40)) renewable energy systems within each ofthe algorithm's defined localities; (2) The normalized performance forthese forty (40) systems will be summed and then divided by forty (40);(3) This results in a statistically significant geographic average whichwill then be recorded on the database; (4) An important feature of thisalgorithm is that much of the complexity is dealt with at the individualrenewable energy system level with the system coefficient. Thesimplicity of the algorithm is important for processor efficiency andongoing data production.

There may be a comparative diagnostics process. Once the normalizedperformance and the geographic average are known for a given renewableenergy system, these two figures can be compared to determine how wellthe system is performing vis-à-vis expectations. The reason the resultsof this are valid regardless of time of year or environmental conditionsis because these factors are all controlled for within the localsampling of related systems. Based on the factors noted above which candegrade system performance, the comparative diagnostics can be used todetermine when a monitored electrical system is performing suboptimally, therefore the comparative value may be “underperforming” orany other term indicating an issue. If the comparative value falls belowcertain thresholds (e.g. 7.5% below the Geographic Average signals asystem issue) these diagnostics can then be used to remediate the issueand improve the system's performance. The diagnostics can be broken outinto periods of different length (24 hours, 7 days and 1 month) whichhave the following benefits: (i) 24 Hour Comparisons: While a 5 minutesegment may show variance between one renewable energy system and thegroup's geographic average, the variance may not be due to any inherentsystem issue (e.g. a single cloud may be temporarily affecting onesystem without impacting others in the vicinity). However, over a 24hour period, these environmental factors are normally controlled for,and any significant variance will reveal a legitimate system issue. Thefact that this is done over a rolling 24 hours means that theinformation will be received by the renewable system owner or serviceprovider relatively quickly, without the requirement of waiting for aweekly or monthly report; (ii) Weekly Comparisons: Though this does notprovide the same sort of timely information that is provided by 24 HourComparisons, the additional data will allow for more accurate diagnosticcomparisons since environmental variables will have even less impact;(iii) Monthly Comparisons: While more accurate than Weekly Comparison,this will be used mostly as a reporting mechanism to show system statusand performance.

The sample system may have at least one inverter (14) in communicationwith the monitored electrical system (e.g. 50, 30). The inverter (14) isan electronic circuit that converts direct current (DC) to alternatingcurrent (AC). There may also be at least one return monitor (18)determining the energy returned to a grid by said at-least one monitoredelectrical system. At least one background constant may be determinedand saved in the data server(s). The monitored electrical system (e.g.30, 50) may be at least partially powered by at least one alternateenergy source. There may be at least one generation monitoring device(e.g. 58), which calculates the energy generated at each consumer'spremises by the monitored electrical system (e.g. 30, 50); at least onecommunication node (64) in communication with each at least onegeneration monitoring device (e.g. 58); at least one data server (10) incommunication with communication node (e.g. 64), wherein the dataserver(s) (10) accept information from the communication node (e.g. 64)to determine the power generated at a first user's premises (100) andcompare the power generated at a first user's premises (100) toComparative Information obtained from at least two monitored electricalsystems (e.g. 102, 104, 106, 108, 110, 112, 114) to determine if thefirst user's monitored electrical system (100) is within a predetermineddeviation from the comparative information. This may provide acomparative value. The communication node may be further comprising adata storage means for storing usage information. For example, thecommunication node (64) may be a computer with a hard drive that acts asa data storage means for storing usage information. The generationmonitoring device may be selected from the group consisting of pulsemeter, temperature meter, electromechanical meter, solid state meter,flow meter, electric meter, energy meter and watt meter. There may alsobe at least one return monitoring device in communication with theinverter which calculates the energy returned to a grid by the system.

The monitored electrical system may be, for example, a solar system,solar panel system, photovoltaic, thermal, wind powered, geothermal,hydropower. A secondary energy source (e.g. 52) may be in communicationwith and at least partially powering the monitored electrical system. Itshould be understood, though, this is only for ancillary power in theevent that the renewable energy source (50) is not capable of entirelypowering the at premise monitored electrical system.

The generation monitoring device may be any type of meter, by way ofexample, this may include a pulse meter, temperature meter,electromechanical meter, solid state meter, flow meter, electric meter,energy meter and watt meter. An installation will have a communicationnode or hub set up at the location with the system. One of thecommunication nodes may act as a hub. These devices connect to theinternet and send the data collected by the nodes to the Server. Theyhave the following properties: The hub has a web server and connects toa standard internet connection (Ethernet). It does not require acomputer or other device to make this connection. Each hub has its ownunique IP or DNS address. The hub is configured by a web browser. Theweb browser allows the hub to have specific nodes assigned to it. Thisset up feature will allow another hub in the area to be set up with itsown nodes so that all can operate wirelessly without disruption. Also,the hub is able to configure specific aspects of the hub, such as theconnection with the server, data recording and time settings and theability to configure the attached nodes, including their recordingproperties.

The hub may connect wirelessly or through wire-line including through ACpower to the various nodes in its network and may handle several nodes,sending up the data of each within a separate data stream to the server.Typically the hub would plug into a standard AC outlet and have LEDs toshow operation and diagnostics. The hub may also record data, so that ifthe Internet connection is ever down, data from the nodes will not belost. It will also have the option of a tamper resistant casing andminor router capabilities—so that it could stand in front of a standardrouter and act as the primary data entry point for a location. The hubwill also be able to operate behind a router. All of the hubs mayconnect to a centralized database for data aggregation. This databasewill be able to relate the information from each node according to thetime recorded. Specific data which will be saved may include: (1) hubIP#/DNS information; (2) node IP#/DNS information/name; (3) Timestampincrement; (4) Hot water flow by unit (gallon or liter) per timeincrement; (5) Electric flow by unit (kilowatts) per time increment; (6)Fuel flow by unit (depends on fuel type) per time increment; and (7)Other information as required (e.g. water temperature).

An installation will typically have one or more generation recordingnodes. In this way, the step of remotely acquiring required data for atleast one monitored electrical system to provide acquired electricalsystem data may be carried out. The generation recording node may betypically connected wirelessly to the hub, and connected directly to theinputs/outputs from the monitored electrical system. They communicateconstantly with the various devices and transfer data which is then sentto the server. They may have the following properties: The firstrequired node connects to a flow meter attached to the Water Tank thatis connected to the Solar Hot Water system. This node will operate as apulse meter, ‘clicking’ whenever a unit (either a gallon or a liter) ofhot water passes from the tank. The second required node connects toeither the electric panel at the switch for the Hot Water tank'selectric power OR to a flow/other meter for gas/oil to the secondaryheater for the Hot Water tank. The node may have a data storage meansfor storing flow/usage information. There may also be other nodes, whichmay be used to measure other aspects of the system and gain even moreaccurate readings. For example: the temperature of the hot water on anongoing basis. The system may be monitored from a remote location (suchas a computer in a different location).

It is envisioned that the present invention provides a set of devices,systems and methods to accurately and remotely measure the utilizedenergy generated from Solar Hot Water (SHW) systems in real-time.Specifically, the data input from a pulse meter (which is connected to aflow meter from the hot water tank) and the data input from a Watt meter(which is connected to an electrical panel for secondary electricalheating in the hot water tank) OR another pulse meter (which isconnected to a flow meter on a fuel line that serves as a secondaryheating source) may be calculated and software used to combine them on acentralized server. The combined data is then used to calculate theutilized energy generated by the Solar Hot Water system by determiningthe total amount of energy represented by the hot water used andsubtracting any secondary energy (e.g. electrical or fuel) that was alsoused to heat the water. With additional calculations which take intoaccount the general starting temperature of the water entering the tankand also subtracting for any energy used for other purposes (e.g.pumping water), the system will be able to isolate the precise utilizedenergy generated by the renewable (i.e. solar) component of the system.This will result in an accurate measurement of the renewable energygenerated and consumed for a given time-period which can then be used tomonitor efficiency, determine the actual payback period of the system,qualify for incentives and carbon credits, etc.

Each installation may have two or more Data Nodes. These are typicallyconnected wirelessly to the Hub, and connected directly to theinputs/outputs from the Solar Hot Water system. They communicateconstantly with the Hub, transferring data which the Hub then sends upto the server. They may have the following properties: The firstRequired Node connects to a flow meter attached to the Water Tank thatis connected to the Solar Hot Water system. This Node will operate as apulse meter, ‘clicking’ whenever a unit (either a gallon or a liter) ofhot water passes from the tank. The second Required Node connects toeither the electric panel at the switch for the Hot Water tank'selectric power OR to a flow/other meter for gas/oil to the secondaryheater for the Hot Water tank. The Node may have a data storage meansfor storing flow/usage information. Together, the data gathered fromthese Required Node connections allow the software on the serve toconvert the utilized hot water into an accurate reading of utilizedsolar energy by subtracting the energy required to by the secondaryheating mechanism. The term utilized generation refers to the energygenerated by the at-premise power system, less any energy that has notbeen consumed by the at premise power system (e.g. the energy used toheat water that remains in the tank and is not subsequently used). Notethat the term “at-premise power system” is one type of monitoredelectrical system, as claimed. There may also be other Nodes, which maybe used to measure other aspects of the system and gain even moreaccurate readings. For example: the temperature of the hot water on anongoing basis. The system may be monitored from a remote location (suchas a computer in a different location).

Typically each Node connects to a specific hub. It is set up to do sothrough the browser interface for the Hub. The connection to the Hub istypically wireless, though these can also be connected through Ethernetwiring. Wireless transmissions between the Hub and Nodes will have dataencryption. There will be the ability to create a tamper resistantcasing around the Node. This is important to ensure the accuracy of theactual power utilized. The Node has two wire input areas for pulses.These, combined with the time stamp, will be sent up to the Server. Thecomputer processor implemented server may be at a remote location. TheNode also has a connection for a Watt sensor. This will have thefollowing characteristics: The Watt sensor can handle 1-3 phase hook upsand will be compatible with clamps as well as loop sensors. According toone preferred embodiment, the basic formula to calculate utilizedgeneration for a given period is as follows:

util=(fl1*temp*cony*dur)=(fl2*dur)

In this formula, util is the utilized generation, or utilized powergenerated, by the SHW system for the period, fl1 is the flow in units ofhot water from the hot water tank during the time increment (flow is theusage for a water heater, it may be other measures for different atpremise power systems), temp variable is the difference between thestarting temperature of the water when it enters the tank and when itleaves. In the basic conversion equation, this will be kept as aconstant, but for systems with material changes in entry and exittemperature, these will be measured and included in the equation. Anexample of this would be for a system in which the cold water pipeentering the system is not insulated and is exposed to outdoorconditions, cony is a conversion constant variable which is the constantfor converting the BTUs required to heat the water from the entry toexit temperature (or temp) into Kilowatts, dur variable is the period.This will generally be a month, though a shorter period may be chosen.The fl2 variable is the flow in units of energy for the secondaryheating source. It is important to note that the calculation will bedifferent if the secondary heating source is provided by fuel. This isrecorded in the same length increments as the fl1 variable.

The components (node (100), hub (102) and server (10) make up therequired core components needed to accurately measures the actual usableoutput from a Solar Hot Water (SHW) system. Essentially, the hub (102)connects to multiple nodes (100) which simultaneously measure thesecondary power going into the system along with the hot water goingout. Controlling for any background power requirements (e.g. forpumping), it can measure the usable BTUs created by solar by analyzingthe measurements at the server (104) level.

It is important to be able to measure the usable energy generated bySolar Hot Water systems (SHW systems). As the most efficient systemsavailable by a significant margin compared to Photovoltaics (PV), SolarHot Water system can provide high-efficiency, inexpensive power today.But not only are they less well known/publicized than PVs, it can bedifficult to precisely prove their effectiveness since there are fewerways to efficiently measure their utilized production than with PVs.This makes accurate payback calculations more difficult, and may preventsome companies from purchasing these systems. Another important reasonto be able to accurately measure the utilized power from SHW systems isto benefit from incentives. While many states have general rebates forSHW system for homeowners, larger installations, which potentially havegreater commercial and environmental benefits are more difficult toapply for since an easy method of accurately monitoring the usable powergenerated and converting it over time into kilowatt hours is not readilyavailable. Also, this would allow the sale/trading of carbon creditsfrom SHW systems. The ability to remotely monitor utilized energy inreal time provides addition capabilities on the part of thosemaintaining the solar systems in terms of their ability to find issuesand increase the systems' efficiency.

Once information regarding utilized generation has been generated, itmay be displayed on a portal for use in the following: determining theexact utilized power generated by the SHW system for a given duration tocalculate the impact of the system (and potentially its actual paybackperiod); calculating utilized power for monitoring and diagnosticsvis-à-vis anticipated performance; Calculating power generated forincentives and carbon credits. To determine the carbon credits, themethod may comprise the step of calculating an equivalent amount ofcarbon which would have been created to generate the power utilized forthe at least one Period to provide a carbon deficit. Also, the methodmay comprise the step of offering carbon credits according to the carbondeficit. The step of calculating carbon deficit may take into accountany energy generated. The Carbon credit Periods may start on the firstof a month and end on the last day of a month. This may match thebilling cycles.

The at least one at-premise monitored electrical system may be a solarsystem, solar panel system, photovoltaic, thermal, wind powered,geothermal, hydropower or any other system. Also, the terms at-premises,on premises and at-premise are interchangeable and equivalent.Additionally, for those interested in heating and cooling their dwellingvia renewable energy, geothermal heat pump systems that tap the constanttemperature of the earth, which is around 7 to 15 degrees Celsius a fewfeet underground, are an option and save money over conventional naturalgas and petroleum-fueled heat approaches. The term at premises renewablepower system does not include conventional natural gas and petroleumfueled heat.

The method may further comprise the steps of: monitoring the system froma remote location; and monitoring the utilized generation from a remotelocation. The method may comprise the steps of: generating an alert whenthe customer variables are a prescribed percentage different thanhistorical averages. The method may also comprise the steps ofmonitoring and storing the consumer's customer variables and utilizedgeneration.

It may be desirable to provide a computer processor implemented methodof determining system configuration information of a monitoredelectrical system (e.g. 502) without the need for user input, the methodcomprising the steps of; constructing a data set of standard performancecurves for at least one system type to provide a data set with at leastone system type and correlated standard performance curves. Differenttypes of systems have different signatures in the form of standardperformance curves from which the system type can be identified. Forexample, a solar photovoltaic system tends to have an energy profilethat looks like FIG. 7, and is dependent on the time of day and weatherconditions. Wind generation systems tend to have an energy profile thatis highly correlated with the wind speed. Residential consumptionpatterns tend peak in late afternoon, with offsets for any distributedgeneration that is located on-site. Patterns in energy data for solarPV, wind, residential consumption, etc. can be identified by comparingthe pattern of the energy in the data stream to typical patterns asdescribed above, with consideration for the time of year and weatherconditions associated with the data stream. Based on the amount of dataavailable, and how well it matches the typical patterns, a level ofconfidence can be assigned to identifying a data stream as coming from aparticular type of system.

The method may comprise the step of saving the data set with at leastone system type and correlated standard performance curves (for example700, as shown in FIG. 7) in at least one data server (516). The methodmay next comprise the step of defining at least one characteristicfeature for each at least one system type to provide at least one systemtype and correlated characteristic feature and saving the at least onesystem type and correlated characteristic feature in the at least onedata server (516). A characteristic feature may be, for example, time ofsunrise, time of sunset, associated timestamps, energy consumption, windsystem output, weather, configuration, time of year, user habits, systemsize, tracker versus fixed, energy profile shape, east west orientation,north-south orientation, homeowner type, heating type, temperaturesensitivity, consumption data, utilized energy, utilized generation,system derate factors and air conditioning status. It is envisioned thatthere may be an infinite number of characteristic features. However, itis only important that a characteristic feature be able to be attributedto a system type. There may also be a number of characteristic featuresassigned to a single system type. There may also be the step ofproviding a timestamp associated with at least one data set and savingthe timestamp associated with at least one data set in the data server.The method may comprise the step of determining the required data toidentify the at least one system type according to at least one ofstandard performance curve and characteristic feature. There may be thestep of remotely acquiring required data for at least one monitoredelectrical system to provide acquired electrical system data; comparingsystem acquired electrical system data to at least one system type andcorrelated standard performance curves and system type and correlatedcharacteristic features to provide system configuration information forat least one monitored electrical system to provide the specific type ofat least one monitored electrical system. The specific type may refer tothe type of monitored electrical system, the location, the installationangle, the system configuration, the model number or any informationregarding that particular unit. The system configuration information maybe selected from the group consisting of location, longitude, systemsize, system type and installation angle. Again, there are an infinitenumber of things that could be system configuration information. Thestandard performance curve may be selected from the group consisting ofenergy production profile, geographic average profile, degradation dueto temperature, east west orientation, north-south orientation,homeowner type, heating type and air conditioning status.

The method may further comprising the step of: determining a geographicaverage performance; comparing at least one monitored electrical systemsperformance to the geographic average performance; alerting at least oneuser when the at least one monitored electrical systems performance is apredetermined amount lower than the geographic average performance. Theuser may be the owner of the monitored electrical system, may be arenter, or simply a person who leases the equipment. It may be desirableto perform the steps of: determining if the monitored electrical systemcan be remotely adjusted; and remotely making a change to said at leastone monitored electrical system. It may be desirable to load backgroundconstants and diagnostic variables into the data server.

The methodology for completing automated remote identification, toconstruct a large data set of example patterns for certain types ofsystems, define certain features that tend to be characteristic of thesystems in the data set, and use either statistical correlationtechniques, or machine learning optimization (e.g. neural networks) todefine classification thresholds, run empirical tests to determine theneeded amount of data (i.e., length of history & granularity) in orderto automatically identify a system type and use the developed thresholdsfeature sets and data history thresholds to automatically classify datastreams according to different system types. It is also possible todetermine the location where a particular solar powered system(generation or consumption) is physically located. This is because thecharacteristics of the monitored data are influenced bygeographic-specific characteristics, like sunrise/sunset times orweather characteristics. As long as the monitored data stream hasassociated timestamps, it is possible to determine the location byfinding a geographic location that would best match the observed energyconsumption or generation characteristics of the monitored data stream.For example, if the type of generation source (or consumption) is known,one can model the expected behavior of this generation or consumptiondata stream under actual recorded weather around the world (includingsunrise sunset times), and the best fitting match statistically islikely to be the actual physical location. A few specific examples ofhow this invention may be applied to determine a device's locationfollow herein. The solar photovoltaic (PV) system's output will peek atsolar noon, so by examining the system's time of peak output (in UTC orsome reference time zone), one can calculate the longitude and timezonea PV system is operating in. The output of solar PV systems are highlydependent upon weather. By maintaining a time history of weatherconditions across a large area (e.g., North America and Europe), andmodeling PV system outputs across all of these geographies, one canmatch the time history of a PV system's output to the geography of datait most closely matches. This matching process can be improved bynarrowing the range of geographic areas (e.g. using the precedinglongitudinal technique), or by improving the estimated model output of aPV system via leveraging known system characteristics (either knownbeforehand or identified as described in the section below about“Identification of system information for a solar PV system”). Outputfrom a wind system is highly dependent on wind conditions. Bymaintaining a time history of weather conditions across a large area,and modeling the wind system outputs across all the locations, one canmatch the time history of a wind system's output to the geographiclocation it most closely matches. Energy consumption by residential orcommercial users tends to be both time-of-day dependent (e.g., peoplecome home from work and turn on the television) and weather dependent(e.g., more air-conditioners will be running on hot days). These timeand weather dependencies make it possible to perform the same type ofstatistical matching exercise on consumption data as is done ongeneration data for renewable energy systems. By maintaining a timehistory of weather conditions across a large geographic area that theconsumption system is known to be within (e.g. North America or Europe),it is possible to statistically match what the most likely location isfor the consumption monitoring system.

Once a broad system type has been identified, it is possible to furtherrefine the understanding of the system in the field by identifying theparticular characteristics of those systems. This can be done byunderstanding the drivers of the performance of the systems in the field(e.g., weather, configuration, time of year, user habits, etc.). Thefollowing are particular configuration parameters for a solar PV systemthat can be identified in an automated fashion. This patent applicationis both for these particular detailed algorithms, as well as the broaderidea illustrated here (i.e., similar types of automated configurationinformation can be determined for other types of systems including wind,consumption, solar thermal, etc.). The basic idea is to identifyfeatures as deviations from a typical PV standard performance curve(700), as shown in Figure Error! Reference source not found. 7. Thefollowing is a non-exhaustive list of example parameters like bedetermined by comparing features of the data stream with the standardperformance curve in FIG. 7. FIGS. 7-12 provide examples of standardperformance curves and acquired electrical system data.

The size of a monitored electrical system, such as a PV system, can beestimated from measured outputs. If little additional system informationis known, the system outputs can simply be scaled for typical PV systemderates (i.e., expected losses from things like resistance in wires,inverter efficiency, etc.). If more detailed information is available onthe system, either from user input, or from automatically derivedparameters as described below, this more detailed information can beused to more finely tune the expected system derate factors, andtherefore more accurately estimate system size. Solar PV tracker systemstend to have a less peaked energy profile, with greater totalgeneration, as shown in FIG. 8. This is because they keep the inclinedPV surface normal to sun, such that it captures more solar radiationearly or late in the day. System matching this type of performanceprofile can be identified as tracker-type systems. The tracker profile(702) has a less peaked energy profile than the fixed (704) profile asdepicted in FIG. 8. In this example, the tracker profile (702) may bethe acquired electrical system data and the fixed profile (704) may bethe standard performance curve. However, it could be reversed, as longas it is saved in the data set as the system type and correlatedstandard performance curves. In this way, either profile could serve asthe standard performance curve or the acquired electrical system data.This applied for each of the curves shown in FIGS. 7-12, as long as weknow what the performance curve is and the associated data set.

Solar PV designers often undersize the inverter for cost saving reasons.If the inverter is substantially undersized, this can show up as shavedpeaks (706) in the PV generation profile. If these shaved peaks appear,they indicate the maximum capacity of the inverter for a particularsystem. An example of these shaved peaks is shown below in FIG. 9, andthey can be easily identified by the flat top, where normally a curvedsurface (708) would appear.

Solar PV cells produce less power under diffuse light conditions (i.e.,cloudy days) than under a bright clear sunny day. Thin-film PV cells arerelatively less impacted by diffuse light, as compared topolycrystalline PV cells. Examining the ratio of system performance onclear sunny days to cloudy days with diffuse light, one candifferentiate between thin-film and crystalline PV systems, as shown inFIG. 10, where it can be seen that an example thin-film PV system isless impacted than a similar-sized crystalline silicon system (i.e., theratio of B/A is greater than C/A) FIG. 10 depicts the impact of diffuselight on crystalline vs. thin film solar PV systems. FIG. 10 depicts the5 minute kWh production by the time of day. As can be seen the clean day(crystalline and thin film) (710) system performance can serve as ameasuring point to the thin film PV on a cloudy day (712) andcrystalline silicon PV on a cloudy day (714). Once the performance of aparticular system is obtained, it may be compared to the standardperformance curves as depicted in FIG. 10 and it may be determined thetype of system.

Another measure of the difference between cell technologies, is thesensitivity of those cells to temperature. At higher temperatures PVmodules will produce less energy. However, the amount of degradationwith an increase in temperature is dependent upon the PV technology. Forexample, FIG. 11 shows how crystalline silicon PV systems are moresignificantly affected by increases in temperature, relative tosimilarly sized thin-film systems. By assessing the amount ofdegradation due to temperature (e.g., comparing the data stream for twodifferent days, where the measured ambient temperature was differentacross the days, using reference cells and various thin-film technologyperformance curves), one can estimate what the likely PV technologyinvolved is.

FIG. 12 depicts a baseline vs. hot-weather degradation impact forthin-film and crystalline silicon PV systems. With respect to east-westorientation: If a PV system is perfectly flat, the distribution ofenergy produced in the morning and the afternoon should be roughly even,as depicted by flat plate line 722 showing no east west tilt. If the PVsystem is angled towards the east more energy will be produced in themorning than the evening, and vice versa if the system has a westerntilt. A western-tilted PV system is illustrated in FIG. 12 as line 724.Examining the skew in the PV production data one can estimate theaggregate east-west angle of the system in question, thus determiningthe angle at which the PV modules are inclined from the data alone. FIG.12 provides an example of how a western-tilted PV system has a skewedgeneration profile.

North-south orientation: the Sun is much higher in the sky in the summerthan in winter, so the amount of PV generation tends to be much higherat solar noon in the summer and then solar noon in the winter, assuminga flat plate panel with no inclination. FIG. 13 depicts PV generationstandard performance curve for a summer day 726, winter with no tilt 728and winter with southern tilt 730. If the solar PV cells are angled moretowards the south, the change in energy output from summer to winterwill be less (and vice versa for Northern angled PV cells), as shown in13. The ratio of summer to winter production (e.g., B/A vs. C/A in FIG.13) is largely determined by the north-south orientation of the PVarray, so with production data that spans summer and winter months, thenorth-south inclination can be estimated.

If a PV system is partially shaded, the shading can be detected as a dipin the otherwise expected smooth generation curve, as illustrated in 14.If this power production dip (as depicted by line 734) consistentlyappears over time, it is indicative of some sort of shading factor(e.g., tree line, adjacent buildings, etc.). Line 734 representsacquired electrical system data for a system having a shading factor.Line 732 represents a standard performance curve. In this way, thepresent invention can detect a potential problem and notify the user.This may be particularly useful, for example, if a tree may be trimmedto reveal the solar panels resulting in increased production. In thisway, the present invention may comprise the step of identifying aresolvable problem (e.g. a tree creating partial shading) and contactingthe consumer (e.g. send the consumer an email) if the system acquiredelectrical system data deviates a predetermined amount from the standardperformance curve.

Substantial information about the configuration of a home or businessthat underlies a energy consumption monitoring system can be acquired byobserving the pattern of consumption data. A number of specific examplesfor this type of information acquisition were defined above for solar PVsystems. The same idea of examining the data stream, and tying it to anunderlying model of how the system works, can be used to test hypothesesfor what underlies the consumption data stream. Hypotheses that provetrue indicate data about the configuration of the home or business forwhich the consumption data is being gathered. The examples provided areintended to describe and provide clarity regarding the presentinvention, but are not intended to be made in a limiting sense.

A computer processor (e.g. 10) implemented method may develop irradiancemapping using a distributed network of solar photovoltaic systems (e.g.102, 104, 106), the method comprising the steps of: selecting apredetermined geographic area having at least five solar photovoltaicsystems to provide a photovoltaic system (107); calibrating thephotovoltaic system (107) and reversing the photovoltaic systemperformance model using a computer processor to solve the irradianceinput value. The step of reversing the photovoltaic system performancemodel using a computer processor to solve the irradiance input value maybe performed according to simple methods. One example may have only twoinputs:

P=A+BT_(m)*H_(i)+CH_(i)+DH_(i) ², where

-   -   T_(m)=PV array temperature    -   H_(i)=incident irradiance    -   P=power generated    -   A, B, C, and D are constants determined by least square fits

The solar panels convert the irradiance to electric energy, at a ratedependent on a large number of factors. There are many possible modelsfor this conversion process, but two of the most significant factors aretemperature and irradiance. Accordingly, this is a simple power model.The temperature may obtained from a third party internet weather feedsource and saved in the at least one data server. Alternatively, thetemperature may be obtained by a temperate probe and saved in a dataserver. The present invention may perform step of calculating irradianceaccording to the irradiance input value, energy output and weather datausing a computer processor to provide a single irradiance point; andmapping at least two said single irradiance points to create anirradiance map. There may be the step of determining an irradiance inputvalue from system performance values, the calibrated system performancemodel and the temperature The energy output may be determined as the DCpower from the solar PV panel is converted to AC power by an inverter. Agateway then measures the AC power generated and communicates the ACpower generation data (plus additional data from the inverter whereavailable) back to a centralized server over the internet as the energyoutput. Using energy output, temperature, system configurationinformation, and other relevant data for the PV performance model,irradiance is calculated for each system in the geographic area. Theirradiance calculations may be smoothed, eliminating outliers andconverging on a good estimate of the average irradiance in the localregion.

A time series sequence of observations in the form of irradiancemeasurements may be ordered in time. Inherent in the collection of thistype of data is some form of variations. There are many methods forreducing the effect due to such variations. This may be referred to as“smoothing” or “reducing the noise”. When applied, these techniques moreclearly reveal the underlying trends of the data. According to oneaspect of the present invention, there may be the step of smoothing atleast two single irradiance points. The generated irradiance data isused to construct a detailed irradiance map of the region, and furthersmooth the data on longer time scales leveraging information fromsatellite models and new PV systems or weather stations that areinstalled in a given area. One manner to accomplish smoothing may be byproviding moving averages. Moving averages rank among the most populartechniques for the preprocessing of time series. They are used to filterrandom “white noise” from the data, to make the time series smoother oreven to emphasize certain informational components contained in the timeseries. Exponential Smoothing is also a very popular scheme to produce asmoothed Time Series. Whereas in Moving Averages the past observationsare weighted equally, Exponential Smoothing assigns exponentiallydecreasing weights as the observation get older. In other words, recentobservations are given relatively more weight in forecasting than theolder observations. Double Exponential Smoothing is better at handlingtrends. Triple Exponential Smoothing is better at handling parabolatrends. An exponentially weighted moving average with a smoothingconstant a, corresponds roughly to a simple moving average of length(i.e., period) n, where a and n are related by:

a=2/(n+1)OR n=(2−a)/a.

Thus, for example, an exponentially weighted moving average with asmoothing constant equal to 0.1 would correspond roughly to a 19 daymoving average. And a 40-day simple moving average would correspondroughly to an exponentially weighted moving average with a smoothingconstant equal to 0.04878. Although there are numerical indicators forassessing the accuracy of the forecasting technique, the most widelyused approach to compare smoothing methods is in using visual comparisonof several forecasts to assess their accuracy and choose among thevarious forecasting methods. In this approach, one must plot (using,e.g., Excel) on the same graph the original values of a time seriesvariable and the predicted values from several different forecastingmethods, thus facilitating a visual comparison. The foregoing example ofsmoothing techniques are provided as examples, as can be appreciated bythose of skill in the art, there are many smoothing techniques the goalof which is to more clearly reveal the underlying trends of the data.

There may be the step of utilizing comparative information from nearbyphotovoltaic systems to provide at least one comparative informationirradiance point; and mapping the at least two single irradiance pointsand at least one comparative information irradiance point to create theirradiance map.

This may also be actual irradiance readings from irradiance sensors. Inthis way, it can supplement the data achieved according to the presentinvention.

This may be repeated for other geographic areas to assemble alarger-scale irradiance map (See FIG. 15 for a sample irradiance map).Note that typically, an irradiance map may provide the amount of solarradiation in kWh/m²/day. There may also be the step of predictingirradiance based on extrapolation of current data and weather forecasts.

There may be the step of automatically determining system configurationinformation for the solar photovoltaic systems; and utilizing the systemconfiguration information to perform the step of reversing thephotovoltaic system performance model using a computer processor tosolve the irradiance input value. This may be accomplished byconstructing a data set of at least one standard performance curve forat least one system type to provide a data set with at least one systemtype and correlated standard performance curves and saving the data setwith at least one system type and correlated standard performance curvesin at least one data server; defining at least one characteristicfeature for each at least one system type to provide at least one systemtype and correlated characteristic feature and saving at least onesystem type and correlated characteristic feature in at least one dataserver; determining the required data to identify at least one systemtype according to at least one of standard performance curve andcharacteristic feature; remotely acquiring the required data for atleast one solar photovoltaic system to provide acquired solarphotovoltaic systems data and saving the acquired solar photovoltaicsystems data in at least one data server; comparing system acquiredsolar photovoltaic systems data to at least one system type andcorrelated standard performance curves and system type and correlatedcharacteristic features to provide system configuration information forat least one solar photovoltaic system to provide the specific type ofat least one solar photovoltaic system.

The present invention is concerned with systems and methods forestimating solar irradiance components (global horizontal irradiance,direct normal irradiance, diffuse horizontal irradiance, plane of arrayirradiance, plane of array direct irradiance, plane of array diffuseirradiance, plane of array ground reflected irradiance) usingmeasurements of plane of array irradiance or global horizontalirradiance, in conjunction with atmospheric models of irradiancecomponents.

Solar irradiance upon a plane of array, or IPoA, is composed direct(HBEAM), diffuse (HDIFF), and ground reflected irradiance (HGRF). In thespecial case of a horizontal plane of array, IPoA is equivalent toglobal horizontal irradiance (GHI) and the ground reflected component is0. Direct normal irradiance (DNI) is the direct irradiance component ofplane of array irradiance where the plane is perpendicular to Sun's raysgiven the current solar position. Diffuse horizontal irradiance (DHI) isthe diffuse irradiance component of horizontal IPoA or GHI.

Measuring solar irradiance requires field deployment of preciselyconfigured scientific instruments, typically an actinometer variant orthe methods described herein. Actinometers are instruments designed tomeasure the heating power of radiation and variants of this instrumentare designed for measuring solar irradiance. One variant, thepyranometer, is used to measure broadband irradiance and can measure GHIor IPoA. The pyranometer is also capable of measuring DHI when outfittedwith a shadow band and sun tracking equipment to obscure directradiation. Another variant, the pyrheliometer, is calibrated for directirradiance and tracks the sun in order to measure DNI. Basicpyranometers are economically feasible for many projects, but the costof tracking equipment required to measure DNI and DHI are oftenprohibitive to deploy at the level of granularity required, so oftentimes only the aggregate GHI or IPoA is measured using sensors in thefield.

The present invention provides methods for calculating an irradiancemodifier for adjusting modeled solar irradiance components according tomeasured GHI or IPoA values. Also described is usage of this methodologyto develop three (3) alternative solar irradiance component estimationmodels. A model for estimating DNI, DHI, and IPoA from measured GHI andan atmospheric solar irradiance model. A model for estimating HBEAM,HDIFF, and HGRF from measured IPoA and an atmospheric solar irradiancemodel. A model for estimating GHI, DNI, and DHI from measured IPoA andan atmospheric solar irradiance model.

The following are variables within the present invention; (1) MEASUREDSOLAR IRRADIANCE DATA: This provides measurements of solar irradiancethat includes GHI or IPoA among other variables. (2) LOCATION, TIME ANDORIENTATION VARIABLES: These are various variables corresponding to alocation and time. These variables include latitude, longitude, date,and time. If the measured data was IPoA, orientation angle and tiltangle are also required. (3) ATMOSPHERIC IRRADIANCE COMPONENT ESTIMATIONCALCULATIONS: These are a set of formulas that estimate the componentsof solar irradiance (i.e., direct, diffuse, and ground-reflectanceirradiance) based on atmospheric conditions. (4) IRRADIANCE MODIFICATIONLOGIC: This is the logic for calculating the irradiance modifier basedon observed and estimated irradiance amounts. (5) GHI BASED DNI, DHI, &IPoA ESTIMATION MODEL: This is the model that utilizes measured GHI andan atmospheric solar irradiance model to estimate DNI, DHI, and IPoA.(6) IPoA BASED HBEAM, HDIFF, & HGRF ESTIMATION MODEL: This is the modelthat utilizes measured IPoA and an atmospheric solar irradiance model toestimate HBEAM, HDIFF, and HGRF. (7) IPoA BASED GHI, DNI, & DHIESTIMATION MODEL: This is the model that utilizes measured IPoA and anatmospheric solar irradiance model to estimate GHI, DNI, and DHI.

DEFINITION OF VARIABLES

GHI_(model)=modeled global horizontal irradiance based on atmosphericmodel

DNI_(model)=modeled direct normal irradiance based on atmospheric model

DHI_(model)=modeled diffuse horizontal irradiance based on atmosphericmodel

IPoA_(model)=modeled plane of array irradiance based on atmosphericmodel

GHI_(measured)=measured Global Horizonal Irradiance from a sensor devicein the field

DNI_(estimated)=estimated direct normal irradiance based on GHImeasurements and model calibration

DHI_(estimated)=estimated diffuse horizontal irradiance based on GHImeasurements and model calibration

IPoA_(estimated)=estimated plane of array irradiance based on GHImeasurements and model calibration

IMOD=irradiance estimate modifier

DNI, DHI, and IPoA Estimation Model Based on Measured GHI

1. Use atmospheric model to calculate GHI_(model), DNI_(model),DHI_(model,) and IPoA_(model)

IMOD=GHI_(measured)/GHI_(model)  2.

DNI_(estimated)=IMOD*DNI_(model)  3.

DHI_(estimated)=IMOD*DHI_(model)  4.

IPoA_(estimated)=IMOD*IPoA_(model)  5.

HBEAM, HDIFF, and HGRF Estimation Algorithm Definition of Variables

IPoA_(model)=modeled plane of array irradiance based on atmosphericmodel

HBEAM_(model)=modeled plane of array direct irradiance based onatmospheric model

HDIFF_(model)=modeled plane of array diffuse irradiance based onatmospheric model

HGRF_(model)=modeled plane of array diffuse irradiance based onatmospheric model

IPoA_(measmed)=modeled plane of array irradiance from a sensor device inthe field

HBEAM_(estimated)=estimated plane of array direct irradiance based onIPoA measurements and model calibration

HDIFF_(estimated)=estimated plane of array diffuse irradiance based onIPoA measurements and model calibration

HGRF_(estimated)=estimated plane of array diffuse irradiance based onIPoA measurements and model calibration

IMOD=irradiance estimate modifier

HBEAM, HDIFF, and HGRF Estimation Model Based on Measured IPoA

1. Use atmospheric model to calculate IPoA_(model), HBEAM_(model),HDIFF_(model) and HGRF_(model)

IMOD=IPoA_(measured)/IPoA_(model)  2.

HBEAM_(estimated)=IMOD*HBEM_(model)  3.

HDIFF_(estimated)=IMOD*HDIFF_(model)  4.

HGRF_(estimated)=IMOD*HGRF_(model)  5.

GHI, DNI, and DHI Estimation Definition of Variables

IPoA_(model)=modeled plane of array irradiance based on atmosphericmodel

GHI_(model)=modeled global horizontal irradiance based on atmosphericmodel

DNI_(model)=modeled direct normal irradiance based on atmospheric model

DHI_(model)=modeled diffuse horizontal irradiance based on atmosphericmodel

IPoA_(measmed)=measured plane of array irradiance from a sensor devicein the field

GHI_(estimated)=estimated global horizontal irradiance based on IPoAmeasurements and model calibration

DNI_(estimated)=estimated direct normal irradiance based on IPoAmeasurements and model calibration

DHI_(estimated)=estimated diffuse horizontal irradiance based on IPoAmeasurements and model calibration

IMOD=irradiance estimate modifier

GHI, DNI, and DHI Estimation Model Based on Measured IPoA

1. Use atmospheric model to calculate IPoA_(model), GHI_(model),DNI_(model), and DHI_(model)

IMOD=IPoA_(measured)/IPoA_(model)  2.

GHI_(estimated)=IMOD*GHI_(model)  3.

DHI_(estimated)=IMOD*DHI_(model)  4.

DHI_(estimated)=IMOD*DHI_(model)  5.

The corrections of field measurements of global horizontal irradiance orplane of array irradiance for diffuse or direct irradiance quantitiescan be used for a variety of applications where it is important to knowwhere the light is direct or diffuse light. Among those applications arethe following: Solar resource assessment (identifying locations wheresolar PV, bio-mass production, etc., could be valuable). Manyapplications of solar resources behave differently according to theproportion of light made up of directly or diffuse light. For example,concentrating solar energy systems work well under directly light, butpoorly under diffuse light, so it is important to understand the amountof light components, not just the total amount of light. The presentinvention may be used to better assess solar resources based on thecomponents of light.

The present invention may be used to evaluate solar projects and providea performance yield of solar projects. Performance of solar energyproduction systems can be done using total sunlight measurements, butusing components of the sunlight is more precise, however. Using thesystems and methods provided herein, the performance yield of systemscan be done more accurately, since the total sunlight measured by aphysical sensor can be disaggregated into components of light.

The present invention may be utilized to provide system degradationanalysis. Along with performance yield, the degradation of systems canbe more accurately modeled using components of light, which can bedetermined using the technology in this application.

The present invention may provide crop growth modeling and providehistorical and current crop yield assessments. Crop growth modeling canbe improved if the diffuse and direct components of light can bemodeled. The present invention provides more accurate estimates of thosecomponents. crop growth, assessing the current state of growth, orestimating the difference in growth between two points in time can beimproved if the diffuse and direct components of light can be modeled.The present invention envisions systems and methods for more accuratelyestimating those components.

The present invention may provide climate modeling. Dust and particulatematter affects the proportion of direct and diffuse light in theatmosphere, because the dust & particulates increase the amount of lightdiffusion. The present invention provide more accurate estimatesregarding the amount of direct and diffuse light in an area, with theuse of a simple inexpensive irradiance sensor the measures total light.Therefore, this technology can be used to more accurately analyze theimpact of dust and particulates in the air (or conversely, thetechnology can be used to estimate the amount of dust in the atmospherebased on the amount of light diffusion).

Direct normal irradiance, diffuse horizontal irradiance and plane ofarray irradiance may be estimated using measured global horizontalirradiance, modeled global horizontal irradiance, modeled plane of arrayirradiance, modeled direct normal irradiance, modeled diffuse horizontalirradiance and using an irradiance modifier.

Plane of array direct irradiance, plane of array diffuse irradiance, andplane of array ground reflected irradiance may be estimated usingmeasured plane of array irradiance, modeled plane of array irradiance,modeled plane of array direct irradiance, modeled plane of array diffuseirradiance, modeled plane of array ground reflected irradiance and usingan irradiance modifier.

Global horizontal irradiance, direct normal irradiance, and diffusehorizontal irradiance may be estimated using measured plane of arrayirradiance, modeled plane of array irradiance, modeled global horizontalirradiance, modeled direct normal irradiance, modeled diffuse horizontalirradiance and using an irradiance modifier.

The present invention provides a computer implemented method ofestimating at least one solar irradiance component, the methodcomprising: obtaining a sensor measurement from an instrument (such asan actinometer, a pyranometer or a pyrheliometer) to provide a measuredglobal horizontal irradiance (GHImeasured), wherein the measured globalhorizontal irradiance (GHImeasured) consists of at least one estimateddiffuse horizontal irradiance (DHIestimated) and an estimated directnormal irradiance (DNIestimated); providing at least one modeledcomponent, wherein at least one of the modeled components is a modeledglobal horizontal irradiance based on an atmospheric model (GHI model);calculating an irradiance estimate modifier (IMOD) in a computing deviceaccording to the measured global horizontal irradiance (GHImeasured) andthe modeled global horizontal irradiance (GHI model); providing at leastestimated one solar irradiance component by a computing device accordingto the irradiance estimate modifier (IMOD) and at least one modeledcomponent. Each step in this method may be provided or input into acomputer.

The at least one modeled component may be selected from the groupconsisting of modeled global horizontal irradiance based on atmosphericmodel (GHImodel), modeled direct normal irradiance based on atmosphericmodel (DNImodel), modeled diffuse horizontal irradiance based onatmospheric model (DHImodel), modeled plane of array irradiance based onatmospheric model (IPoAmodel), modeled plane of array direct irradiancebased on atmospheric model (HBEAMmodel), modeled plane of array diffuseirradiance based on atmospheric model (HDIFFmodel) and modeled plane ofarray ground reflected irradiance (HGRFmodel).

The estimated solar irradiance component may be selected from the groupconsisting of global horizontal irradiance (GHI), direct normalirradiance (DNI), diffuse horizontal irradiance (DHI), plane of arrayirradiance (IPOA), plane of array direct irradiance (HBEAM), plane ofarray diffuse irradiance (HDIFF) and plane of array ground reflectedirradiance (HGRF).

According to one aspect of the present invention, the step of obtaininga sensor measurement may be obtained from an pyranometer outfitted witha shadow band and sun tracking equipment to obscure direct radiation.The step of obtaining a modeled global horizontal irradiance based on anatmospheric model (GHI_(model)) is according to at least one of weatherdata and satellite imagery.

There may be the step of calibrating at least one of an estimated directnormal irradiance (DNI_(estimated)) and an estimated diffuse horizontalirradiance (DHI_(estimated)). The step of calibrating may be correctedfor solar position without ground reflected irradiance due to horizontalpositioning.

Another aspect of the present invention provides a computer implementedmethod of estimating at least one solar irradiance component, the methodcomprising: obtaining a sensor measurement (by way of example this maybe obtained from an instrument such as an actinometer, a pyranometer anda pyrheliometer) to provide a measured plane of array irradiance(IPoA_(measured)), wherein the measured plane of array irradiance(IPoA_(measured)) consists of at least an estimated plane of arraydirect irradiance (HBEAM_(estimated)), an estimated plane of arraydiffuse irradiance (HDIFF_(estimated)) and plane of array groundreflected irradiance (HGRF_(estimated)); providing at least one modeledcomponent, wherein at least one of the modeled components is a modeledplane of array irradiance based on an atmospheric model (IPoA_(model));calculating an irradiance estimate modifier (IMOD) in a computing deviceaccording to the measured plane of array irradiance (IPoA_(measured))and modeled plane of array irradiance based on an atmospheric model(IPoA_(model)); providing at least one estimated solar irradiancecomponent by a computing device according to the irradiance estimatemodifier (IMOD) and at least one modeled component.

Each step in this method may be provided or input into a computer orcomputing device. It should be understood that a computing device may beany microprocessor based device. By way of example, it may be acomputer, smartphone or any device that is capable of performingcomputations. Each step of the present invention that requirescomputations may be performed by the computing device.

The at least one modeled component of the present invention may beselected from the group consisting of modeled global horizontalirradiance based on atmospheric model (GHI_(model)), modeled directnormal irradiance based on atmospheric model (DNI_(model)), modeleddiffuse horizontal irradiance based on atmospheric model (DHI_(model)),modeled plane of array irradiance based on atmospheric model(IPoA_(model)), modeled plane of array direct irradiance based onatmospheric model (HBEAM_(model)), modeled plane of array diffuseirradiance based on atmospheric model (HDIFF_(model)) and modeled planeof array ground reflected irradiance (HGRF_(model)).

The adjusted solar irradiance component of the present invention may beselected from the group consisting of global horizontal irradiance(GHI), direct normal irradiance (DNI), diffuse horizontal irradiance(DHI), plane of array irradiance (IPoA), plane of array directirradiance (HBEAM), plane of array diffuse irradiance (HDIFF) and planeof array ground reflected irradiance (HGRF).

The step of obtaining a sensor measurement may be obtained from anpyranometer outfitted with a shadow band and sun tracking equipment toobscure direct radiation. The step of obtaining a modeled globalhorizontal irradiance based on an atmospheric model (GHI_(model)) may beaccording to at least one of weather data and satellite imagery.

It should be understood that the foregoing relates to preferredembodiments of the invention and that modifications may be made withoutdeparting from the spirit and scope of the invention as set forth in thefollowing claims.

1. A computer implemented method of estimating at least one solarirradiance component, the method comprising: obtaining a sensormeasurement from an instrument to provide a measured global horizontalirradiance (GHI_(measured)), wherein the measured global horizontalirradiance (GHI_(measured)) consists of at least an estimated diffusehorizontal irradiance (DHI_(estimated)) and an estimated direct normalirradiance (DNI_(estimated)); providing at least one modeled component,wherein at least one of the modeled components is a modeled globalhorizontal irradiance based on an atmospheric model (GHI_(model));calculating an irradiance estimate modifier (IMOD) in a computing deviceaccording to the measured global horizontal irradiance (GHI_(measured))and the modeled global horizontal irradiance (GHI_(model)); providing atleast one estimated solar irradiance component by a computing deviceaccording to the irradiance estimate modifier (IMOD) and at least onemodeled component.
 2. A method as in claim 1, wherein the at least onemodeled component is selected from the group consisting of modeledglobal horizontal irradiance based on atmospheric model (GHI_(model)),modeled direct normal irradiance based on atmospheric model(DNI_(model)), modeled diffuse horizontal irradiance based onatmospheric model (DHI_(model)), modeled plane of array irradiance basedon atmospheric model (IPoA_(model)), modeled plane of array directirradiance based on atmospheric model (HBEAM_(model)), modeled plane ofarray diffuse irradiance based on atmospheric model (HDIFF_(model)) andmodeled plane of array ground reflected irradiance (HGRF_(model)).
 3. Amethod as in claim 1, wherein the estimated solar irradiance componentis selected from the group consisting of global horizontal irradiance(GHI), direct normal irradiance (DNI), diffuse horizontal irradiance(DHI), plane of array irradiance (IPoA), plane of array directirradiance (HBEAM), plane of array diffuse irradiance (HDIFF) and planeof array ground reflected irradiance (HGRF).
 4. A method as in claim 1,wherein the instrument is selected from the group consisting of anactinometer, a pyranometer and a pyrheliometer.
 5. A method as in claim1, wherein the step of obtaining a sensor measurement is obtained froman pyranometer outfitted with a shadow band and sun tracking equipmentto obscure direct radiation.
 6. A method as in claim 1, wherein the stepof obtaining a modeled global horizontal irradiance based on anatmospheric model (GHI_(model)) is according to at least one of weatherdata and satellite imagery.
 7. A method as in claim 1, furthercomprising the step of calibrating at least one of an estimated directnormal irradiance (DNI_(estimated)) and an estimated diffuse horizontalirradiance (DHI_(estimated)).
 8. A method as in claim 1, wherein saidstep of calibrating is correcting for solar position without groundreflected irradiance due to horizontal positioning.
 9. A computerimplemented method of estimating at least one solar irradiancecomponent, the method comprising: obtaining a sensor measurement toprovide a measured plane of array irradiance (IPoA_(measured)), whereinthe measured plane of array irradiance (IPoA_(measured)) consists of atleast an estimated plane of array direct irradiance (HBEAM_(estimated)),an estimated plane of array diffuse irradiance (HDIFF_(estimated)) andplane of array ground reflected irradiance (HGRF_(estimated)); providingat least one modeled component, wherein at least one of the modeledcomponents is a modeled plane of array irradiance based on anatmospheric model (IPoA_(model)); calculating an irradiance estimatemodifier (IMOD) in a computing device according to the measured plane ofarray irradiance (IPoA_(measured)) and modeled plane of array irradiancebased on an atmospheric model (IPoA_(model)); providing at least oneestimated solar irradiance component by a computing device according tothe irradiance estimate modifier (IMOD) and at least one modeledcomponent.
 10. A method as in claim 9, wherein the at least one modeledcomponent is selected from the group consisting of modeled globalhorizontal irradiance based on atmospheric model (GHI_(model)), modeleddirect normal irradiance based on atmospheric model (DNI_(model)),modeled diffuse horizontal irradiance based on atmospheric model(DHI_(model)), modeled plane of array irradiance based on atmosphericmodel (IPoA_(model)), modeled plane of array direct irradiance based onatmospheric model (HBEAM_(model)), modeled plane of array diffuseirradiance based on atmospheric model (HDIFF_(model)) and modeled planeof array ground reflected irradiance (HGRF_(model)).
 11. A method as inclaim 6, wherein the adjusted solar irradiance component is selectedfrom the group consisting of global horizontal irradiance (GHI), directnormal irradiance (DNI), diffuse horizontal irradiance (DHI), plane ofarray irradiance (IPoA), plane of array direct irradiance (HBEAM), planeof array diffuse irradiance (HDIFF) and plane of array ground reflectedirradiance (HGRF).
 12. A method as in claim 6, wherein the step ofobtaining a sensor measurement is obtained from an instrument selectedfrom the group consisting of an actinometer, a pyranometer and apyrheliometer.
 13. A method as in claim 6, wherein the step of obtaininga sensor measurement is obtained from an pyranometer outfitted with ashadow band and sun tracking equipment to obscure direct radiation. 14.A method as in claim 6, wherein the step of obtaining a modeled globalhorizontal irradiance based on an atmospheric model (GHI_(model)) isaccording to at least one of weather data and satellite imagery.